Hydrocarbons, such as oil and gas, may be recovered from various types of subsurface geological formations. The formations typically consist of a porous layer, such as limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot rise through the nonporous layer, and thus, the porous layer forms a reservoir in which hydrocarbons are able to collect. A well is drilled through the earth until the hydrocarbon bearing formation is reached. Hydrocarbons then are able to flow from the porous formation into the well.
In what is perhaps the most basic form of rotary drilling methods, a drill bit is attached to a series of pipe sections referred to as a drill string. The drill string is suspended from a derrick and rotated by a motor in the derrick. A drilling fluid or “mud” is pumped down the drill string, through the bit, and into the well bore. This fluid serves to lubricate the bit and carry cuttings from the drilling process back to the surface. As the drilling progresses downward, the drill string is extended by adding more pipe sections.
When the drill bit has reached the desired depth, larger diameter pipes, or casings, are placed in the well and cemented in place to prevent the sides of the borehole from caving in. Cement is introduced through a work string. As it flows out the bottom of the work string, fluids already in the well, so-called “returns,” are displaced up the annulus between the casing and the borehole and are collected at the surface.
Once the casing is cemented in place, it is perforated at the level of the oil bearing formation to create openings through which oil can enter the cased well. Production tubing, valves, and other equipment are installed in the well so that the hydrocarbons may flow in a controlled manner from the formation, into the cased well bore, and through the production tubing up to the surface for storage or transport.
This simplified drilling and completion process, however, is rarely possible in the real world. Hydrocarbon bearing formations may be quite deep or otherwise difficult to access. Thus, many wells today are drilled in stages. An initial section is drilled, cased, and cemented. Drilling then proceeds with a somewhat smaller well bore which is lined with somewhat smaller casings or “liners.” The liner is suspended from the original or “host” casing by an anchor or “hanger.” A seal also is typically established between the liner and the casing and, like the original casing, the liner is cemented in the well. That process then may be repeated to further extend the well and install additional liners. In essence, then, a modern oil well typically includes a number of tubes wholly or partially within other tubes.
Moreover, hydrocarbons are not always able to flow easily from a formation to a well. Some subsurface formations, such as sandstone, are very porous. Hydrocarbons are able to flow easily from the formation into a well. Other formations, however, such as shale rock, limestone, and coal beds, are only minimally porous. The formation may contain large quantities of hydrocarbons, but production through a conventional well may not be commercially practical because hydrocarbons flow though the formation and collect in the well at very low rates. The industry, therefore, relies on various techniques for improving the well and stimulating production from formations. In particular, various techniques are available for increasing production from formations which are relatively nonporous.
One technique involves drilling a well in a more or less horizontal direction, so that the borehole extends along a formation instead of passing through it. More of the formation is exposed to the borehole, and the average distance hydrocarbons must flow to reach the well is decreased. Another technique involves creating fractures in a formation which will allow hydrocarbons to flow more easily. Indeed, the combination of horizontal drilling and fracturing, or “frac'ing” or “fracking” as it is known in the industry, is presently the only commercially viable way of producing natural gas from the vast majority of North American gas reserves.
Fracturing typically involves installing a production liner in the portion of the well bore which passes through the hydrocarbon bearing formation. In shallow wells, the production liner may actually be the casing suspended from the well surface. In either event, the production liner is provided, by various methods discussed below, with openings at predetermined locations along its length. Fluid, most commonly water, then is pumped into the well and forced into the formation at high pressure and flow rates, causing the formation to fracture and creating flow paths to the well. Proppants, such as grains of sand, ceramic or other particulates, usually are added to the frac fluid and are carried into the fractures. The proppant serves to prevent fractures from closing when pumping is stopped.
A formation usually is fractured at various locations, and rarely, if ever, is fractured all at once. Especially in a typical horizontal well, the formation usually is fractured at a number of different points along the bore in a series of operations or stages. For example, an initial stage may fracture the formation near the bottom of a well. The frac job then would be completed by conducting additional fracturing stages in succession up the well.
Some operators prefer to perform a frac job on an “open hole,” that is without cementing the production liner in the well bore. The production liner is provided with a series of packers and is run into an open well bore. The packers then are installed to provide seals between the production liner and the sides of the well bore. The packers are spaced along the production liner at appropriate distances to isolate the various frac zones from each other. The zones then may be fractured in a predetermined sequence. The packers in theory prevent fluid introduced through the liner in a particular zone from flowing up or down the well bore to fracture the formation in areas outside the intended zone.
Certain problems arise, however, when an open hole is fractured. The distance between packers may be substantial, and the formation is exposed to fluid pressure along that entire distance. Thus, there is less control over the location at which fracturing of a formation will occur. It will occur at the weakest point in the frac zone, i.e., the portion of the well bore between adjacent packers. Greater control may be obtained by increasing the number of packers and diminishing their separation, but that increases the time required to complete the frac job. Moreover, even if packers are tightly spaced, given the extreme pressures required to fracture some formations and the rough and sometimes frangible surface of a well bore, it may be difficult to achieve an effective seal with a packer. Thus, fluid may flow across a packer and fracture a formation in areas outside the intended zone.
In part for such reasons, many operators prefer to cement the production liner in the well bore before the formation is fractured. Cement is circulated into the annulus between the production liner and well bore and is allowed to harden before the frac job is commenced. Thus, frac fluid first penetrates the cement in the immediate vicinity of the inner openings before entering and fracturing the formation. The cement above and below the liner openings serves to isolate other parts of the formation from fluid pressure and flow. Thus, it is possible to control more precisely the location at which a formation is fractured when the production liner is first cemented in the well bore. Cementing the production liner also tends to more reliably isolate a producing formation than does installing packers. Packers seat against a relatively small portion of the well bore, and even if an effective seal is established initially, packers may deteriorate as time passes.
There are various methods by which a production liner is provided with the openings through which frac fluids enter a formation. In a “plug and perf” frac job, the production liner is made up from standard lengths of casing. The liner does not have any openings through its sidewalls. It is installed in the well bore, either in an open bore using packers or by cementing the liner, and holes then are punched in the liner walls. The perforations typically are created by so-called perforation guns which discharge shaped charges through the liner and, if present, adjacent cement.
The production liner typically is perforated first in a zone near the bottom of the well. Fluids then are pumped into the well to fracture the formation in the vicinity of the perforations. After the initial zone is fractured, a plug is installed in the liner at a point above the fractured zone to isolate the lower portion of the liner. The liner then is perforated above the plug in a second zone, and the second zone is fractured. That process is repeated until all zones in the well are fractured.
The plug and perf method is widely practiced, but it has a number of drawbacks. Chief among them is that it can be extremely time consuming. The perf guns and plugs must be run into the well and operated individually, often times at great distance and with some difficulty. After the frac job is complete, it also may be necessary to drill out or otherwise remove the plugs to allow production of hydrocarbons through the liner. Thus, many operators prefer to frac a formation using a series of frac valves.
Such frac valves typically include a cylindrical housing that may be threaded into and forms a part of a production liner. The housing defines a central conduit through which frac fluids and other well fluids may flow. Ports are provided in the housing that may be opened, most commonly by actuating a sliding sleeve. Once opened, fluids are able to flow through the ports and fracture a formation in the vicinity of the valve.
The sliding sleeves in such valves traditionally have been actuated either by creating hydraulic pressure behind the sleeve or by dropping a ball on a ball seat which is connected to the sleeve. Typical multi-stage fracking systems will incorporate both types of valves. Halliburton's RapidSuite sleeve system and Schlumberger's Falcon series sleeves, for example, utilize a hydraulically actuated “initiator” valve and a series of ball-drop valves.
More particularly, the production liner in those systems is provided with a is hydraulically actuated sliding sleeve valve which, when the liner is run into the well, will be located near the bottom of the well bore in the first fracture zone. The production liner also includes a series of ball-drop valves which will be positioned in the various other fracture zones extending uphole from the first zone. The seat on each valve must be big enough to allow passage of the balls required to actuate every valve below it. Conversely, the ball used to actuate a particular valve must be smaller than the balls used to actuate every valve above it. Thus, starting with the lowermost valve, the ball-drop valves will have increasingly larger ball seats as they move up the liner.
A frac job will be initiated by increasing fluid pressure in the production liner. The increasing pressure will actuate the sleeve in the bottom, hydraulic valve, opening the ports and allowing fluid to flow into the first fracture zone. Once the first zone is fractured, a ball is dropped into the well and allowed to settle on the ball seat of the ball-drop valve immediately uphole of the first zone. The seated ball isolates the lower portion of the production liner and prevents the flow of additional frac fluid into the first zone. Continued pumping will shift the seat downward, along with the sliding sleeve, opening the ports and allowing fluid to flow into the second fracture zone. The process then is repeated with each ball-drop valve uphole from the second zone until all zones in the formation are fractured.
Such systems may incorporate up to about twenty ball-drop valves and have been used successfully in many well completions. Using a series of valves avoids the time consuming process of running and setting perf guns and plugs. A formation may be fractured in multiple zones more quickly by dropping a succession of balls into the well to successively open the valves and isolate downhole zones.
Regardless of the method, however, multistage fracturing operations require that flow into one zone be shut off before, or more or less concurrently with commencing flow into the next zone. In plug and perf methods, as discussed above, the perforations are left open and plugs are installed between each zone. In liners provided with a series of valves, at least in theory the valve could be provided with a mechanism that not only would slide the sleeve to its open position, but that also would slide it shut when it was time to commence flow through another valve. Such mechanisms, however, are not typically present in sliding sleeve valves. More typically, as in the RapidSuite and Falcon systems discussed above, the ports are left open and flow into a zone is shut off by a shutting off flow into the valve. That is, balls dropped into a liner will settle on a ball is seat of a valve, and the seated ball will isolate those portions of the liner downhole from the valve.
While seated balls can effectively isolate downhole valves during a multi-stage fracturing operation, once fracturing of the well bore has been completed the ball seats may present significant restrictions in the liner which can reduce the subsequent flow of hydrocarbons up the liner. That is especially true when the liner has a large number of ball-drop valves. The lower ball seats may be quite small. Thus, it may be necessary to drill out the liner to remove the seats prior to production. Such operations can be time consuming and costly.
Moreover, many conventional valves are poorly suited for incorporation into a liner that will be cemented in place prior to fracturing the formation. The central conduit in many valves contains profiles and recesses that may cause cement passing through the valve as the liner is cemented in place to hang up in the valve. A cement wiper plug is typically pumped through the liner, but the presence of profiles and recesses may make it hard for the plug to cleanly wipe cement out of the valve. Ball seats, for example, may diminish the efficacy of a wiper plug. Thus, an operator may have to incur the expense and trouble of drilling out a liner before it can be cemented in the well.
The ability to selectively inject fluid into various zones in a well bore is important not only in fracturing, but in other processes for stimulating hydrocarbon production. Aqueous acids such as hydrochloric acid may be injected into a formation to clean up the formation. Water or other fluids may be injected into a formation from a “stimulation” well to drive hydrocarbons toward a production well. In many such stimulation processes, as in fracturing a well, the ability to selectively flow fluids out a series of valves may improve the efficacy and efficiency of the process.
It also may be necessary to stimulate production from existing wells which have a perforated liner. For example, new plugs may be installed to isolate perforations in an existing liner. Fluid may be injected into the formation through the isolated perforations, after which additional plugs are installed to isolate and inject stimulation fluids through is other perforations. Such processes, however, also can be costly, and for older, marginal wells, may be avoided in favor of using “perforation balls” or “ball sealers.”
Such processes are commenced by pumping stimulation fluids into a perforated well. The fluids necessarily will flow preferentially into those portions of a formation offering the least resistance. After a quantity of fluid has been pumped into the initial, lowest resistance zone, a plurality of ball sealers are pumped into the liner. The ball sealers most commonly are relatively small, spherically shaped balls, but they may have other geometries. In any event, the ball sealers will flow preferentially into the perforations adjacent the lowest resistance zone, plugging those perforations. At that point stimulation fluids begin to flow preferentially through the perforations adjacent those zones offering the next lowest resistance. Pumping is continued for a period of time and another batch of ball sealers is pumped into the well to plug those perforations. The process is repeated until the zones adjacent all perforations have been stimulated.
Using ball sealers usually will be less costly and time consuming than setting and drilling out or retrieving a series of plugs. The technique is crude and imprecise, however, for a number of reasons. Because flow is always preferentially into the zone of least resistance, there is no control over the order in which zones are stimulated and the operator may end up stimulating zones that did not require stimulation in order to ensure that the target zone was stimulated. Although the simplified description above may suggest otherwise, there also is little control over the amount of fluids pumped into a particular zone. Fluid may initially flow preferentially into one zone, but then because of changing resistance, may begin to flow preferentially into another zone.
Perforations in a liner also may not be uniform, either as formed or after years of exposure to well fluids. Perforation openings may be elongated due to the casing curvature and the angle at which the perforation gun was discharged. Perforations also may have been formed with burrs or uneven surfaces, or they may corrode or accumulate scale. Thus, it may be difficult to shut off flow through perforations in a well with any given size or configuration of ball sealer. Various solutions to such issues have been proposed, such as the use of sealing agents as disclosed in U.S. Pat. Publ. 2011/0226479 of P. Tippet et al., but the use of ball sealers remains problematic.
The statements in this section are intended to provide background information related to the invention disclosed and claimed herein. Such information may or may not constitute prior art. It will be appreciated from the foregoing, however, that there remains a need for new and improved methods for operating valves used to stimulation well formations and to tubular assemblies used to stimulate formations. Such disadvantages and others inherent in the prior art are addressed by various aspects and embodiments of the subject invention.